1. Technical Field
The present invention generally relates to method for improving the total energy demand required to separate carbon dioxide from an aqueous ionic absorbent solution in a post-combustion carbon capture process.
2. Description of the Related Art
The removal of carbon dioxide from natural gas is commercially practiced now in order to obtain natural gas, which satisfies sales specifications or other process-dependent requirements. Carbon dioxide is one of the primary combustion products as fuel is burned and is emitted into the atmosphere as a waste flow in the flue gas. Removal of carbon dioxide from the flue gas is not commonly practiced at the present time. As the efforts to control CO2 emissions into the atmosphere increase, the removal of carbon dioxide from flue gas may become necessary at an industrial scale in order to satisfy carbon dioxide emission requirements which may be set by air pollution control authorities. The CO2 removal process from natural gas may not be directly applied to the CO2 removal from flue gas since the conditions of these two processes are very different. The process of CO2 removal from flue gas and then recovery of CO2 is generally called a post-combustion carbon capture process. One of the more promising post-combustion carbon capture processes utilizes an absorbent solution to remove CO2 from the flue gas and then recovers CO2 from the absorbent solution.
Several processes for removing carbon dioxide from gases are known. Examples of such processes for carbon dioxide separation and capture include chemical absorption, physical and chemical adsorption, low-temperature distillation, gas-separation membranes, mineralization/biomineralization, and vegetation. The carbon dioxide absorption process is a unit operation where one or more components in a gas mixture are dissolved in a liquid (solvent). The absorption may either be a purely physical phenomenon or involve a chemical reaction, such as the reaction between carbon dioxide and an amine. Generally, the liquid solvent is an aqueous amine solution for the removal of carbon dioxide from gas streams.
An example of an absorption process is the process for removing carbon dioxide from flue gas by means of monoethanolamine (MEA) or diethanolamine (DEA). The flue gas is led into an absorption column where it comes into contact with MEA or DEA which absorbs the carbon dioxide molecules. Typically, these amines, MEA and DEA, are used as 25 to 30 wt. % amine in an aqueous solution. The amine solution enters the top of an absorption tower while the carbon dioxide containing gaseous stream is introduced at the bottom. The solvent is then led to a desorption process where the liquid is heated, and the carbon dioxide molecules are removed from the solvent by means of a desorption column. Carbon dioxide and water emerge from the amine solution and the water is separated by condensing the water vapor in a heat exchanger. The solvent is cooled and then recycled back, to the absorption tower for additional carbon dioxide absorption.
Solvent chemistry, corrosion, and viscosity considerations limit the amine strength to about 30 wt. % MEA. At flue-gas carbon dioxide partial pressures (e.g., 0.04 to 0.15 atm), the carbon dioxide-rich (“rich”) solvent loading is about 0.42 to 0.45 mol CO2/mol MEA and the CO2-lean (“lean”) solvent loading is about 0.15 to 0.17 mol CO2/mol MEA. The difference in loading (0.25 to 0.3 mol CO2/mol MEA) sets the circulation rate of the amine and influences capital and operating costs.
MEA also has disadvantages in that it has several mechanisms of loss, and a continuous makeup of MEA is required for a flue gas CO2 removal process or post-combustion carbon capture process. For example, MEA degrades in the presence of oxygen from the flue gas. Thus, to limit the oxidative degradation, corrosion inhibitors may be used. MEA also degrades into heat-stable salts (HSS) from reaction with carbon dioxide. To solve this problem, a reclaimer would be added on the regenerator to separate the HSS from the amine solution to provide suitable makeup MEA. Lastly, the volatility of MEA results in the treated flue gas containing in excess of 500 ppmv MEA when leaving the absorber to the vent. To address this, a wash section is added at the top of the absorber and makeup water is added to scrub the MEA from the treated flue gas. The mixture is then sent down the column along with the remaining lean solvent to absorb carbon dioxide from the incoming flue gas. Water washing can cut the MEA emissions to about 3 ppmv.
MEA may also degrade over time thermally, thereby limiting the temperature of operation in the absorber and regenerator. With a cooled flue gas inlet temperature of about 56° C., the absorber column may operate at a bottoms temperature of 54° C. and a pressure of 1.1 bar while the regenerator may operate at a bottoms temperature of 121° C. (2 bar saturated steam) at 1.9 bar. For 30 wt. % MEA, the amine reboiler steam temperature is kept at less than 150° C. (4.7 bar saturated steam) to limit thermal degradation.
MEA also degrades in the presence of high levels of NOx and SOx which are common in facilities that burn coal and fuel oil. However, if carbon dioxide removal from a high NOx and SOx containing flue gas is desired, separate process facilities such as SCR (Selective Catalytic Reduction) and FGD (Flue Gas Desulfurization) are needed for removal of NOx and SOx, respectively.
Other drawbacks with amine solutions such as MEA and DEA are 1. Intensive energy requirements: During the regeneration step, heating energy is required to break the chemical bonds between the absorbed CO2 and solvent. Energy is also required to generate steam within the amine regenerator to strip the CO2 from the solvent. For some particularly strongly-absorbing amines (e.g., MEA) and for large, circulation rates, this energy requirement can be very high and represents a significant operating expense. Due to the high energy requirements, CO2-rich amine solutions are only partially regenerated to a lower CO2 loading (CO2-lean state) during the regeneration step.
Another disadvantage with the use of MEA is the solution of 30 wt. % MEA in water has a relatively high heat of absorption for CO2, i.e., a heat of absorption of 82 kJ/mol of CO2. Solvents with a high heat of absorption will further result in an increased energy demand for stripping CO2 from the loaded MEA solution.
The total energy demand is an important parameter for estimating the cost of operating the post-combustion flue gas carbon capture process as well as a measure of the performance and viability of the absorption solvent. Accordingly, an increase in the total energy demand for stripping CO2 from the absorption solvent will result in an increase in the operating cost for the post-combustion capture process.
Because of the significant costs involved, proper amine selection for the absorption solvent requires careful evaluation of these factors for the specific application since the criticality of these factors varies for different amines. In other words, one faces a trade-off and optimization between benefits and costs. Nevertheless, in general, the main disadvantage for amine-based CO2 removal processes remains the high energy consumption requirements.
Accordingly, in order to have an improved, low cost, post-combustion carbon dioxide removal technology that is better than those known in the art (i.e., 30 wt. % MEA and similar aqueous amines), it is desirable to develop a method for improving the total energy demand required to separate carbon dioxide (CO2) from an aqueous absorbent solution (i.e., stripping (or solvent regeneration)) in a post-combustion carbon capture process.